1. Field of Invention
This invention concerns a system for conducting wireline formation testing. More particularly, the invention concerns an improved method for determining formation permeability and initial sandface pressure in low permeability zones utilizing a wireline formation test tool.
2. Description of Related Art
The use of wireline well logging ("wireline logging") has long been an important technique utilized in the exploration and production of oil and gas. Generally, a sensitive measuring instrument is lowered on an armored cable into a wellbore, the cable having at least one conductor therein, and measurements are made at different depths in the well. The measuring instrument may include tools or sondes intended to perform electrical investigation, nuclear investigation, acoustic investigation or to test formation characteristics. Electrical logs are typically used to locate hydrocarbon reserves, whereas nuclear logs are employed to determine the volume of hydrocarbons in the reserves, typically by determining the porosity of the materials in potential production depths or zones identified by the electrical logs. Formation pressure testing logs ("formation testing logs") are utilized to determine the mobility or ease with which the reserves may be produced by determining the formation production zone pressure and permeability.
A wellbore is typically filled with a drilling fluid such as water or a water-based or oil-based drilling fluid. The density of the drilling fluid is usually increased by adding certain types of solids, such as various salts and other additives, that are suspended in solution. These salts and other additives are often referred to as "drilling muds." The solids increase the hydrostatic pressure of the wellbore fluids to help maintain the well and keep fluids of surrounding formations from flowing into the well. Uncontrolled flow of fluids into a well can sometimes result in a well "blowout."
The solids within the drilling fluid create a "mudcake" as they flow into a formation by depositing solids on the inner wall of the wellbore. The wall of the wellbore, along with the deposited solids, tends to act like a filter. The mudcake also helps prevent excessive loss of drilling fluid into the formation. The static pressure in the well bore and the surrounding formation is typically referred to as "hydrostatic pressure." Relative to the hydrostatic pressure in the wellbore, the hydrostatic pressure in the mudcake decreases rapidly with increasing radial distance. Pressure in the formation beyond the mudcake gradually tapers off with increasing radial distance outward from the wellbore.
As shown in FIG. 1A, pressure is typically distributed in a wellbore through a formation as shown by the pressure profile 100. Pressure is highest at the wellbore's inner wall, i.e., the inside surface of the mudcake at point and is equal to the hydrostatic pressure Pm 102 inside the wellbore. The mudcake acts like a filter, restricting the flow of fluids from the high pressure of the wellbore into the relatively lower pressure of the formation. Thus, there is a rapid pressure drop through the mudcake. The pressure at point 104 at the interface between the mudcake and the formation (the "sandface pressure") is substantially lower than the pressure at point 102 at the inside surface of the mudcake. Conventional mudcakes are typically between about 0.25 and 0.5 inch thick, and polymeric mudcakes are often about 0.1 inch thick. Beyond the mudcake, the formation exhibits a gradual pressure decrease illustrated by the slope 106.
Ideally, pressure and permeability of the formation need to be known in the production zone prior to the setting of the casing. Several known methods may be used to determine this. One method is the use of rotary sidewall cores. However, analysis of rotary sidewall cores require up to 24 hours and must be corrected to estimate in situ permeabilities, i.e. as they actually exist in the formation. The sidewall core analysis is generally performed on dry samples which may exhibit different permeabilities when compared with water saturated permeabilities which may exist in situ. This is especially true in zones exhibiting low formation permeability on the order of 1.0-0.001 millidarcies. The zones of low formation permeability are often referred to as "tight zones." Dry tight zone permeabilities dry based on sidewall core analysis can vary almost an order of magnitude when compared to water saturated permeabilities encountered in situ.
Formation testing tools may also be used to predict the pressure of a hydrocarbon bearing formation around a well, and to thereby better understand the hydrocarbon's producibility. The structure of a formation tester and its operation are explained with reference to FIG. 2. The pressures seen or detected by the formation tester during operation are set forth in FIG. 3. In a typical formation testing operation, a formation tester 200 is lowered into a wellbore 202 with a wireline cable 201, as illustrated in FIG. 2A. Inside the wellbore 202, the formation tester 200 resides within drilling fluid 204. The drilling fluid 204 typically forms a layer of mudcake 206 on the walls of the wellbore 202, in accordance with known techniques. In many cases, equipment (not shown) for conducting other types of logs, such as gamma ray logs, may be attached to the same wireline cable as the formation tester, below and/or beneath the formation tester 200. The operation of the formations tester 200 may be readily understood with reference to the structure of the tester 200 set forth in FIG. 2 and FIG. 3 graph of the pressures detected by pressure sensor 216 during the operation of the formation tester 200.
After the formation tester 200 is lowered to the desired depth of the wellbore 202, along with any other equipment connected to the wireline cable 201, pressure in a flow line 219 is equalized to the hydrostatic pressure of the wellbore by opening an equalization valve 214. Since the equalization valve 214 is located at a high point of the tester 200, opening the valve 214 permits bubbles and lighter fluids to escape out into the wellbore 202 through the flow lines 215. Then, a pressure sensor 216 may be used to measure the hydrostatic pressure (FIG. 3, 302) of the drilling fluid. In the illustrated embodiment, the equalization valve 214 is a two-way valve that simply enables or disables fluid flow through the flow lines 215.
After the equalization valve 214 is again closed, the tester 200 is secured in place by extending hydraulically actuated feet 208 and an opposing isolation pad 210 against opposite sides of the wellbore walls. The pad 210 surrounds a hollow probe 212 (sometimes called a "snorkel"), which is connected to plumbing internal to the tester 200, as described below. Initially, as the pad 210 is extended against the wellbore wall, the pressure inside the probe 212 slightly increases. This pressure increase (FIG. 3, 304) followed by a decrease is illustrated in FIG. 3 by the set pressure (FIG. 3, 306) prior to the start of the pretest.
Fluid from the formation 222 is drawn into the tester 200 by mechanically retracting a pretest piston 218. The retracting of the protest piston 218 creates a pressure drop at the probe 212, thereby drawing formation fluid into the probe 212, the flowline 219, and a pretest chamber 220. The isolation pad 210 helps prevent borehole fluids 204 from flowing outward through the mudcake 206 and circling back into the probe 212 and the chamber 220. Thus, the isolation pad 210 "isolates" the probe 212 from the borehole fluids 204, helping to ensure that the measurements of the probe 212 are representative of the pressure in the formation 222. When the piston 218 stops retracting, formation fluid continues to enter the probe 212 until the pressure differential between the chamber 220 and the formation 222 is minimized. The drawdown pressure (p.sub.dd, 308, FIG. 3) corresponds to the pressure detected by the sensor 216 while the formation fluid is being withdrawn from the formation. The buildup pressure increase (p.sub.bu, 310, FIG. 3) corresponds to the pressure detected while formation fluid pressure is building up again after the drawdown period, i.e., after the pretest piston 218 stops moving. This final buildup pressure is frequently referred to as the "sandface pressure." It is usually assumed that the sandface pressure is close to the formation pressure. The drawdown 308 and buildup 310 pressures are used in determining formation permeability. The rate of the pressure buildup is slowed, primarily due to the cushion effect of the flowline 219 volume, which is generally greater than the volume of pretest chamber 220. This flowline cushion effect renders much of the p.sub.bu plot versus time unusable for known pressure/flow analysis techniques such as the radial or "Horner" analysis or spherical models. This flowline distortion in the buildup pressure does not dissipate until the difference in the recorded pressure and the final buildup pressure is small. If further fluid samples are desired in addition to the fluid in the chamber 220, control valves 224 may be individually opened and closed at selected times to capture fluid samples in supplemental chambers 226. When the formation tester 200 is disengaged from the wellbore wall, the detected formation pressure 312 increases rapidly due to the removal of pressure applied by the pad 210.
After the desired measurements are made, the formation tester 200 may be raised or lowered to a different depth to take another series of tests. At each depth, the tests usually require a short period of time, such as five minutes. However, tight zone testing requires a considerably greater time for the buildup pressure to occur, often as much as one hour, thereby magnifying the effects of flowline distortion. This flowline distortion effect is one of the major factors affecting pressure measurements in tight zones. The fluid samples are examined and the measured fluid pressures are analyzed to determine the fluid mobility, as influenced by factors such as the porosity and permeability of the formation fluids.
Another effect which can distort wireline formation pressures is the effect of wellbore fluids entering the formation. Normally, the mudcake prevents excessive loss of the drilling fluid into the formation. When the mudcake formation approaches a steady-state condition, a pressure gradient is established in the formation as illustrated in FIG. 1A. The pressure in the well bore (hydrostatic pressure) drops rapidly across the mudcake then gradually reduces to formation pressure. This pressure gradient can be predicted using Darcy's law.
Pressure readings in formation testers are adversely affected in "supercharged regions," FIG. 1B. In a supercharged region, the mudcake fails to adequately hold the drilling fluid in the wellbore, and the drilling fluid penetrates the formation creating an "invaded zone." In the invaded zone, the fluid pressure is increased. The effect of supercharging on the operation of a formation pressure tester is illustrated by the curve 305 in FIG. 3. With supercharging, the pressures detected by the formation tester is initially higher (301) than without supercharging (302). During drawdown, as the pretest piston 218 retracts, the pressure rapidly decreases (302), but normalizes at a level greater than the non-supercharged formation pressure (308). When the pretest piston 218 stops, fluid pressure rapidly builds up again (309), and pressure increases and eventually normalizes to a value corresponding to the supercharged formation pressure. When the formation pressure testing tool is disengaged from the wellbore, the detected formation pressure rises again (311).
Pressure measurements may also be adversely affected if the mudcake permeability is nearly the same as the permeability of the zone. The sandface pressure measured by the formation pressure will approach hydrostatic pressure. Under these conditions, the mud filtrate is not inhibited from invading the formation. This is particularly true in low permeability zones where the sealing influence of the mudcake is small. In low permeability formation, flow into the probe can be very slow during a buildup test. If the mudcake has little sealing quality, mud filtrate ca seep through the mudcake into the formation at a rate comparable to that of the rate being drawn into the tester probe 212. FIG. 4 shows how mud filtrate flows into the formation and is diverted to production into the probe 212. This communication with the wellbore can produce an additional supercharge effect on the pressure buildup, making permeability and initial sand face pressure estimates difficult.
There are two mechanisms that cause the flow of formation fluid into the probe 212 in the buildup state. First, the compressibility of the fluid in the formation 222 creates a pressure differential between the probe 212 and the formation pressure. The second mechanism is the compressibility of the fluid in the flow line 219 in contact with the probe 212. This fluid is decompressed, creating an additional pressure differential between the probe 212 and the formation 222. However, many conventional analysis techniques ignore these mechanisms, assuming that the wellbore pressure is isolated from the formation near the probe and that little or no fluid flows across the mudcake. As discussed above, fluid flow across the wellbore boundary may be significant due to the permeability of the mudcake, and such flow may be especially acute in supercharged regions. Therefore, known methods for measuring formation pressure are not as accurate as some people would like, especially when applied in supercharged regions.
Several known methods are utilized to compensate for the distorting effect of supercharging by measuring formation pressure at various depths and by making estimations based on deviations from a linear pressure relationship. Although this approach might be adequate for some applications, it is limited because it fails to actually quantify the effect of supercharging, and therefore lacks the level of accuracy some people require. These problems associated with supercharging effects, flowline and mudcake invasion severely limit the effectiveness of formation testing in tight zones.